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Duke Energy Carolinas

South Carolina 2017 Integrated Resource Plan

(Annual Report)

September 1, 2017

Confidential

PUBLIC


South Carolina

PUBLIC

2017 IRP Annual Report

Integrated Resource Plan

September 1, 2017

2

DEC SC 2017 IRP TABLE OF CONTENTS

SECTION: PAGE:

ABBREVIATIONS ...................................................................................................................... 3

1. INTRODUCTION............................................................................................................... 6

2. 2017 IRP SUMMARY ........................................................................................................ 7

3. IRP PROCESS OVERVIEW........................................................................................... 11

4. SIGNIFICANT CHANGES SINCE 2016 IRP ............................................................... 14

5. LOAD FORECAST .......................................................................................................... 34

6. ENERGY EFFICIENCY AND DEMAND SIDE MANAGEMENT ........................... 46

7. DEVELOPMENT OF THE RESOURCE PLAN .......................................................... 69

8. SHORT-TERM ACTION PLAN .................................................................................... 81

9. CONCLUSIONS ............................................................................................................... 89

10. DUKE ENERGY CAROLINAS OWNED GENERATION ......................................... 91

11. NON-UTILITY GENERATION & WHOLESALE .................................................... 101

12. CROSS-REFERENCE OF IRP REQUIREMENTS & SUBSEQUENT ORDERS ........... 104


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ABBREVIATIONS

AMP Aging Management Programs

CAIR Clean Air Interstate Rule

CAMR Clean Air Mercury Rule

CC Combined Cycle

CCR Coal Combustion Residuals

CCS Carbon Capture Sequestration

CECPCN Certificate of Environmental Compatibility and Public Convenience and Necessity

CFL Compact Fluorescent Light bulbs

CHP Combined Heat and Power

CO2 Carbon Dioxide

COD Commercial Operation Date

COL Combined Construction and Operating License

CPCN Certificate of Public Convenience and Necessity

CPP Clean Power Plan

IPI Manufacturing Industrial Production Index

CSAPR Cross State Air Pollution Rule

CT Combustion Turbine

DC Direct Current

DEC Duke Energy Carolinas

DEP Duke Energy Progress

DOE Department of Energy

DSM Demand Side Management

EE Energy Efficiency Programs

EGU Electric Generating Unit

EIA Energy Information Administration

EPA Environmental Protection Agency

EPC Engineering, Procurement, and Construction

EPRI Electric Power Research Institute

FERC Federal Energy Regulatory Commission

FGD Flue Gas Desulfurization

FLG Federal Loan Guarantee

GALL Generic Aging Lessons Learned Report

GHG Greenhouse Gas

HB 589 Competitive Energy Solutions for North Carolina (House Bill 589)

HRSG Heat Recovery Steam Generator

HVAC Heating, Ventilation and Air Conditioning

IGCC Integrated Gasification Combined Cycle

IRP Integrated Resource Plan

IS Interruptible Service

ILR Inverter Load Ratio

ITC International Trade Commission

ITC Investment Tax Credit

JDA Joint Dispatch Agreement`

KW kilowatt


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ABBREVIATIONS (CONT.)

LCR Table Load, Capacity, and Reserve Margin Table

LEED Leadership in Energy and Environmental Design

LOLE Loss of Load Expectation

MACT Maximum Achievable Control Technology

MATS Mercury Air Toxics Standard

MMBtu 1 million British Thermal Units

MW Megawatt

MWh Megawatt-hour

NAAQS National Ambient Air Quality Standards

NC North Carolina

NCDAQ North Carolina Division of Air Quality

NCEMC North Carolina Electric Membership Corporation

NCMPA1 North Carolina Municipal Power Agency #1

NC REPS North Carolina Renewable Energy and Energy Efficiency Portfolio Standard

NCTPC NC Transmission Planning Collaborative

NCUC North Carolina Utilities Commission

NERC North American Electric Reliability Corp

NGCC Natural Gas Combined Cycle

NOx Nitrogen Oxide

NRC Nuclear Regulatory Commission

NSPS New Source Performance Standard

NUREG Nuclear Regulatory Commission Regulations

OATT Open Access Transmission Tariff

O&M Operations and Maintenance

ONS Oconee Nuclear Station

PC Pulverized Coal

PEV Plug-In Electric Vehicles

PMPA Piedmont Municipal Power Agency

PPA Purchase Power Agreement

PSCSC Public Service Commission of South Carolina

PV Photovoltaic

PVRR Present Value Revenue Requirements

PURPA Public Utility Regulatory Policies Act

QF Qualifying Facility

REC Renewable Energy Certificates

REPS Renewable Energy and Energy Efficiency Portfolio Standard

RFP Request for Proposal

RIM Rate Impact Measure

RPS Renewable Portfolio Standard

SAE Statistically Adjusted End-Use Models

SAT Single-Axis Tracking

SC South Carolina

SC DER South Carolina Distributed Energy Resource Program

SCE&G South Carolina Electric & Gas


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ABBREVIATIONS (CONT.)

SCR Selective Catalytic Reduction

SEPA Southeastern Power Administration

SERC SERC Reliability Corporation

SG Standby Generation

SIP State Implementation Plan

SLR Subsequent License Renewal

SO2 Sulfur Dioxide

SRP-LR Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants

SRP-SLR Standard Review Plan for Review of Subsequent License Renewal Applications for Nuclear Power

Plants

STAP Short-Term Action Plan

TAG Technology Assessment Guide

TRC Total Resource Cost

The Company Duke Energy Carolinas

The Plan Duke Energy Carolinas Annual Plan

UCT Utility Cost Test

UEE Utility Energy Efficiency Programs

U.S. United States

VACAR Virginia/Carolinas

VAR Volt Ampere Reactive


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1. INTRODUCTION:

For more than a century, Duke Energy Carolinas (DEC or the Company) has provided affordable

and reliable electricity to customers in South Carolina (SC) and North Carolina (NC) now

totaling more than 2.5 million in number. The Company continues to serve its customers by

planning for future demand requirements in the most reliable and economic way possible using

increasingly clean forms of energy.

Historically, each year, as required by the Public Service Commission of South Carolina

(PSCSC) and the North Carolina Utilities Commission (NCUC), DEC submits a long-range

planning document called the Integrated Resource Plan (IRP) detailing potential infrastructure

needed to match the forecasted electricity requirements for our customers over the next 15 years.

As per the PSCSC Order No. 98-502 Approving Least-Cost Integrated Resource Planning

Process, the Company is providing a Short-Term Action Plan, a 15-year plan and other pertinent

information compliant with said Order.

The Company files separate IRPs for South Carolina and North Carolina. However, the IRP

analyzes the system as one DEC utility across both states including customer demand, energy

efficiency (EE), demand side management (DSM), renewable resources and traditional supply-

side resources. As such, the quantitative analysis contained in both the South Carolina and North

Carolina filings is identical, while certain sections dealing with state-specific issues such as state

renewable standards or environmental standards may be specific to that states IRP.


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2. 2017 IRP SUMMARY:

Each year, as required by the PSCSC, DEC submits an IRP detailing potential infrastructure

needed to meet the forecasted electricity requirements for its customers over the next 15 years.

The 2017 IRP is the best projection of how the Companys capacity and energy portfolio will

look over the next 15 years, based on current data assumptions. This projection may change over

time as variables such as the projected load forecasts, fuel price forecasts, environmental

regulations, technology performance characteristics and other outside factors change.

The proposed plan will meet the following objectives:

Provide reliable electricity especially during peak demand periods by maintaining

adequate reserve margins. Peak demand refers to the highest amount of electricity being

consumed for any given hour across DECs entire system.

Add new resources at the lowest reasonable cost to customers. These resources include a

balance of EE, DSM, renewable resources, nuclear facilities, hydro generation and

natural gas generation.

Improve the environmental footprint of the portfolio by meeting or exceeding all federal,

state and local environmental regulations.

In the 2017 IRP, DEC developed four cases which reflect updates to the 2016 IRP base case. The

first case, or the Base Case, is an update to the presented base case in the 2016 IRP, which

includes the expectation of future carbon legislation and no relicensing of existing nuclear

units. Additionally, a No Carbon Case was developed in which no carbon legislation, without

nuclear relicensing, is considered. Finally, given the uncertainty of new and existing nuclear

generation, the Base Case and No Carbon Case were also evaluated with relicensing of existing

nuclear units. All results presented in this IRP represent the Base Case without nuclear relicensing,

except where otherwise noted. As discussed in more detail throughout this report, two significant

updates in this years IRP are developments around the Lee Nuclear project and changes in

DECs renewable energy forecast.

Lee Nuclear

On December 19, 2016, the Company received the Combined Construction and Operating

License (COL) for the Lee Nuclear Project from the United States Nuclear Regulatory

Commission (U.S. NRC). On August 25, 2017, DEC filed a request to cancel the Lee Nuclear

Project as that project was originally envisioned and included in prior IRPs. Also, that

cancellation request is now pending before the North Carolina Utilities Commission (NCUC) in


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Docket Nos. E-7, Sub 819 and E-7 Sub 1146. DECs decision to cancel the project resulted from

events that have occurred subsequent to receipt of the Lee Nuclear COL. These events include

the AP-1000 technology owner, designer and engineer, Westinghouse, and its parent company,

Toshiba Corporation, indicating that they intend to exit the nuclear construction business in the

U.S., including the Lee Project; the subsequent bankruptcy of Westinghouse, and the substantial

cost increases and schedule delays associated with the Vogtle and V.C. Summer new nuclear

construction projects; the latter of which South Carolina Electric & Gas Company (SCE&G) and

project joint owner, Santee Cooper, recently canceled.

In addition to these developments, revised projections indicate that new nuclear baseload capacity is

needed only under a carbon-constrained scenario with the assumption of no existing nuclear re-

licensing. Even in that scenario, the added capacity would not be needed until much later in the 15-

year planning horizon (2031, 2033) than projected in the 2016 IRP.

Over the next year, the Company will continue to monitor and analyze key developments on factors

impacting the potential need for future new baseload nuclear generation. Such factors include

further developments on the Vogtle project, progress on existing unit relicensing efforts and

changes in fuel prices and carbon policy.

Renewable Energy

The Company continues to aggressively pursue additional cost-effective renewable resources as

a growing part of its energy portfolio. The Companys commitment, coupled with supporting

legislation such as South Carolinas Distributed Energy Resource Program Act (SC DER

Program) and North Carolinas Renewable Energy and Energy Efficiency Portfolio Standard

(NC REPS), have led to significant growth in renewable resource development in the Carolinas.

Furthermore, on July 27, 2017, North Carolina Governor Cooper signed into law the Competitive

Energy Solutions for North Carolina bill or House Bill 589 (HB 589). As discussed in more detail

in Section 4.b. of this report, HB 589 calls for the establishment of a competitive procurement

process by which the Company will pursue additional solar resources in its South Carolina and

North Carolina service territory, provided that they are cost-effective for consumers.

Commensurately, the update contained in this years IRP reflects the initial forecast of increases in

renewable additions as a result of HB 589.


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It must be noted, however, that at the time of this report filing, the rules, regulations and details

surrounding the implementation of HB 589 are still under development. As these rules are finalized

and as the Company gains experience with the new competitive procurement process, updated

forecasts will be presented in subsequent IRPs.

In addition to the Lee Nuclear and Renewable Energy updates, other changes since the 2016 IRP

are discussed in this document. Those changes include:

Load Forecast

Combined Heat & Power (CHP) Projections

Resource Adequacy

Fuel Costs

Carbon Assumptions

Technology Construction and Operating Costs

Transmission Planned and Under Construction

As shown in the 2017 IRP Base Case, projected incremental needs are driven by load growth and

the retirement of aging generation resources and expiration of purchase power contracts. The

2017 IRP seeks to achieve a reliable, economic long-term power supply through a balance of

incremental renewable resources, EE, DSM, and traditional supply-side resources planned over

the coming years which allows the Company to maintain a diversified resource mix while also

providing increasingly clean energy. Chart 2-A represents the incremental investments required to

meet future needs.


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Chart 2-A 2018 and 2032 Base Case Winter Capacity Mix and Sources of Incremental

Capacity


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3. IRP PROCESS OVERVIEW:

To meet the future needs of DECs customers, it is necessary for the Company to adequately

understand the load and resource balance. For each year of the planning horizon, the Company

develops a load forecast of cumulative energy sales and hourly peak demand. To determine total

resources needed, the Company considers the peak demand load obligation plus a 17% minimum

planning reserve margin.

The projected capability of existing resources, including generating units, EE and DSM, renewable

resources and purchased power contracts, is measured against the total resource need. Any deficit

in future years will be met with a mix of additional resources that reliably and cost-effectively meet

the load obligation and planning reserve margin while complying with all environmental and

regulatory requirements.

Growth in Peak

Demand and Energy

Consumption

+ Resource Retirements = New Resource Needs

It should be noted that DEC considers the non-firm energy purchases and sales associated with the

Joint Dispatch Agreement (JDA) with Duke Energy Progress (DEP) in the development of its

independent Base Case. To accomplish this, DEC and DEP plans are determined simultaneously to

minimize revenue requirements of the combined jointly dispatched system while maintaining

independent reserve margins for each company.

For the first time in the 2016 IRP, DEC developed resource plans that also include new resource

additions driven by winter peak demand projections inclusive of winter reserve requirements. The

completion of a comprehensive reliability study demonstrated the need to include winter peak

planning in the IRP process. The study recognized the growing volatility associated with winter

morning peak demand conditions such as those observed during recent polar vortex events. The

study also incorporated the expected significant growth in solar that provide valuable assistance in

meeting summer afternoon peak demands on the system but do little to assist in meeting demand for

power on cold winter mornings. As discussed in more detail in the Resource Adequacy section, the

significant penetration of solar resources and the associated impact on summer versus winter

reserves is the primary driver for the Companys shift to winter capacity planning. Based on results

of the reliability study, DEC is now utilizing a winter planning reserve margin of 17% in its

planning process.


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For the 2017 Update IRP, the Company presents a Base Case with a carbon tax beginning in 2026.

The Clean Power Plan (CPP) rule that was finalized on August 3, 2015 by the EPA is under

interagency review for potential repeal. As a result, the timing and details of any potential future

carbon legislation are highly uncertain. While future carbon legislation is unknown, the Company

feels that it is prudent to continue to plan for this scenario, as well as other potential future

scenarios. Furthermore, a primary focus of this update IRP is the Short-Term Action Plan (STAP),

which covers the period 2018 to 2022. It was determined that the inclusion of the carbon tax did not

have a significant impact on the STAP, and therefore the majority of the data presented in this report

represents the Base Case.

Figure 3-A represents a simplified overview of the resource planning process in the update years

(odd years) of the IRP cycle.


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Figure 3-A Simplified IRP Process

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4. SIGNIFICANT CHANGES FROM THE 2016 IRP:

As an initial step in the IRP process, all production cost modeling data is updated to include the

most current data. Throughout the year, best practices are implemented to ensure the IRP best

represents the Companys planning assumptions including load forecast, generation system,

conservation programs, renewable energy and fuel costs. The data and methodologies are regularly

updated and reviewed to determine if adjustments can be made to further improve the IRP process

and results.

As part of the review process certain data elements with varying impacts on the IRP, inevitably

change. A discussion of new or updated data elements that have the most substantial impact on the

2017 IRP is provided below.

a) Load Forecast

The Company continues to utilize the statistically adjusted end use models (SAE) provided by

ITRON to forecast sales and peaks with reasonable results.

Each time the forecast is updated, the most currently available historical and projected data is used.

The Spring 2017 forecast which was used in the development of the Companys 2017 IRP utilizes:

Moodys Analytics January 2017 base economic projections

End use equipment and appliance indexes reflecting the 2016 update of ITRONs end-use

data, which is consistent with the Energy Information Administrations 2016 Annual

Energy Outlook

A calculation of normal weather using the period 1987-2016

Additional focus is being placed on the hourly shaping of sales, which plays a critical role in

forecasting summer and winter peaks. While much of this work is ongoing and will be incorporated

in the 2018 IRPs, the Company continues to review the weather sensitivity of winter and summer

peaks, as well as the hourly shaping of behind-the-meter solar, utility sponsored energy efficiency

programs (UEE), electric vehicles, and other variables.

Additional focus is also being placed on Duke's load research sample data, to gain a better

understanding of historical hourly demand trends, winter and summer peaking characteristics by

customer class, and minimums by customer class, in continuous efforts to improve forecast

accuracy.


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Table 4-A depicts the projected average annual growth rates of several key drivers from DECs

Spring 2017 Forecast.

Table 4-A Key Drivers

2018-2032

Real Income 2.7%

Manufacturing Industrial Production Index (IPI) 1.3%

Population 1.6%

In addition to economic, demographic, and efficiency trends, the forecast also incorporates the

expected impacts of utility sponsored energy efficient programs, as well as projected effects of

electric vehicles and behind-the-meter solar technology.

The results of the Spring 2017 Forecast as compared to Spring 2016 Forecast is presented in Table

4-B below.

Table 4-B 2017 Load Forecast Growth Rates vs. 2016 Load Forecast Growth Rates

(Retail and Wholesale Customers)

2017 Forecast

(2018 2032)

2016 Forecast

(2017 2031)

Summer

Peak

Demand

Winter

Peak

Demand

Energy

Summer

Peak

Demand

Winter

Peak

Demand

Energy

Excludes impact of

new EE programs 0.7% 1.0% 0.7% 1.3% 1.4% 1.1%

Includes impact of

new EE programs 0.4% 0.9% 0.4% 1.2% 1.3% 1.0%

b) Renewable Energy

The growth of renewable generation in the United States continues to outpace that of non-renewable

generation. In 2016, more than 16,000 megawatts (MW) of wind and solar capacity were installed


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nationwide compared to approximately 10,000 MW for natural gas, coal, nuclear, and other

technologies.1

North Carolina ranked in the top five in the country in solar capacity added in 2016, second behind

only California in total solar capacity online. Duke Energys compliance with NC REPS and the

Public Utilities Regulatory Policy Act (PURPA) as well as the Federal Investment Tax Credit (ITC)

were key factors behind the high penetration of solar in the state. North Carolinas current favorable

avoided cost rate and 15-year contract terms for qualifying facilities (QFs) under PURPA have

contributed to record numbers of projects in the interconnection queue, with the DEC and DEP

combined solar queue representing more than 7,000 MW.

To reduce the dependence on PURPA while continuing to support solar growth in a sustainable and

economically attractive manner, on July 27, 2017 Governor Cooper signed into law the

Competitive Energy Solutions for North Carolina bill or House Bill 589 (HB 589). The law

reduces the maximum size of standard contracts offered to solar projects to 1 MW and reduces the

contract term to 10 years.

HB 589 also introduces a competitive procurement process for renewable resources including large-

scale solar facilities that continues to enable third-party and utility-owned renewable development.

Capacity referred to as the Transition MW in this document represents the total capacity of

projects in the combined Duke Balancing Authority area that are (1) already connected; or (2) have

entered into purchase power agreements and interconnection agreements as of the end of the 45-

month competitive procurement period, provided that they are not subject to curtailment or

economic dispatch. HB 589 targets 2,660 MW of competitively procured renewable resources over

a 45-month period, which may vary based on the amount of Transition MW at the end of the 45-

month period. It is expected that 3,500 MW of Transition MW will exist in the combined Duke

Balancing Authority area at the end of the 45-month period. The capacity additions from the

competitive procurement will be in addition to the expected 3,500 MW of Transition MW.

Projects in both North Carolina and South Carolina are eligible for the competitive procurement

process.

Growing customer demand, the federal ITC, and declining installed solar costs make solar capacity

the Companys primary renewable energy resource in the 2017 IRP. The 2017 IRP makes the

following key assumptions regarding renewable energy:

1 All renewable energy MW represent MW-AC (alternating current) unless otherwise noted.


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Installed solar capacity increases in DEC from 889 MW in 2018 to 2,890 MW in 2032;

Achievement of the SC DER Program goal of 120 MW of solar capacity located in DEC-

SC;

Compliance with NC REPS continues to be met through a combination of solar, other

renewables, EE, and Renewable Energy Certificate (REC) purchases;

and

Passage of HB 589 and continuing solar cost declines drive solar capacity growth above and

beyond NC REPS requirements.

Interconnection Queue and the Transition

Through the end of 2016, DEC had more than 500 MW of third party utility scale solar on its

system, with approximately 200 MW interconnecting in 2016. When renewable resources were

evaluated for the 2017 IRP, DEC reported another approximately 35 MW of third party solar under

construction and more than 1,500 MW in the interconnection queue. Table 4-C depicts the

interconnection queue for DEC as of June 30, 2017.

Table 4-C DEC QF Interconnection Queue (as of June 30, 2017)

Utility FacilityState Energy Source Type

Number of

Pending Projects

Pending Capacity

(MW AC)

DEC NC Biogas * 1 0

Biomass 3 11

Hydroelectric 1 4

Landfill Gas 1 2

Solar 137 1,220

NC Total 143 1,237

SC Landfill Gas 1 5

Natural Gas * 1 0

Other 1 0

Solar 57 630

SC Total 60 635

DEC Total 203 1,872

* No Capacity entered into system


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Projecting future solar connections from the interconnection queue has presented a significant

challenge due to the large number of project cancellations and ownership transfers. If the aggregate

capacity in the Transition exceeds 3,500 MW, the competitive procurement volume of 2,660 MW

will be reduced by the excess amount; conversely, if the Transition falls short of 3,500 MW the

Companies will conduct additional competitive procurement.

DECs contribution to the Transition depends on a number of variables including connecting

projects under construction, the number of projects in the queue with power purchase and/or

interconnection agreements, SC DER Program Tier I, and capacity connected as a result of the RFP

for NC REPS compliance issued in the Fall of 2016.

The DEC RFP for NC REPS compliance is expected to be the greatest contributor of Transition

MW beyond the over 500 MW currently connected as more than 300 MW of solar may connect to

meet the 750,000 MWHs requested in the RFP. In total, DEC may contribute roughly one-quarter of

the Transition MW with DEP accounting for the remaining three-quarters.

NC REPS Compliance

DEC remains committed to meeting the requirements of NC REPS, including the poultry waste,

swine waste, and solar set-asides, and the general requirement, which will be met with additional

solar, hydro, biomass, landfill gas, wind, and energy efficiency resources. DECs long-term general

compliance needs are expected to be met through a combination of renewable resources, including

solar RECs obtained through the HB 589 competitive procurement process.

HB-589 Competitive Procurement and Utility-Owned Solar

DEC continues to evaluate utility-owned solar additions to support its NC compliance targets and to

grow its renewables portfolio. For example, DEC has recently connected two new utility-scale solar

projects in NC as part of its efforts to encourage emission free generation resources and help meet

its NC compliance targets, totaling 75 MW-AC:

Monroe Solar Facility 60 MW, located in Union County, NC placed in service on March

29, 2017; and

Mocksville Solar Facility 15 MW, located in Davie County, NC placed in service on

December 16, 2016.


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As mentioned above, HB 589 calls for 2,660 MW of additional solar in the Carolinas, which may

vary depending upon how the actual Transition MW compare to the initial 3,500 MW estimate.

RFPs will be issued over a 45-month period under the competitive procurement process; DEC may

own up to 30% of the competitive procurement volume it self-develops. DEC will also evaluate the

potential for acquiring facilities where appropriate. HB 589 does not stipulate a limit for DECs

option to acquire third party projects. Since the majority of the solar projects connected during the

Transition will be in DEPs territory, DEC is expected to have the majority of the competitive

procurement projects, helping to balance the portfolios and mitigate additional operational

challenges in DEP.

HB 589 requires that competitive bids are priced below utilitys avoided cost rates, as approved by

the NCUC, or it will not be selected. Therefore, the cost of solar is a critical input for forecasting

how much of the competitive procurement will materialize. Avoided cost forecasts are subject to

variability due to changes in factors such as natural gas and coal commodity prices, system

energy and demand requirements, the level and cost of generation ancillary service

requirements and interconnection costs. Changes in these factors will result in changing

avoided cost values over the upcoming years with the potential to impact the cost-effectiveness

of future competitive procurement solicitations.

Similarly, solar costs are also influenced by a number of variables. Panel prices have decreased at a

significant rate and are expected to continue to decline. However, there are political factors, such as

the Suniva International Trade Commission (ITC) case, that have the potential to increase panel

prices. Additional factors that could put upward pressure on solar costs include direct

interconnection costs, as well as costs incurred to maintain the appropriate operational control of the

facilities. 2

Finally, as panel prices have decreased, there has been more interest in installing single-

axis tracking (SAT) systems and/or systems with higher inverter load ratios (ILR) which change the

hourly profile of solar output and increase expected capacity factors. DEC will incorporate different

configurations further in the 2018 IRP.

In summary, there is a great deal of uncertainty in both the future avoided cost value of solar

and the expected price of solar installations in the years to come. As a result, the Company

2 In April, 2017, Suniva officially filed a petition to the ITC under Section 201 of the Trade Act of 1974. Suniva is

requesting relief against imports from all geographic sources and requesting both a minimum price on crystalline silicon

photovoltaic modules (initially $0.78/W) and a tariff on cells (initially $0.40/W). As expected, the petition only applies

to crystalline silicon. (GTM Research Suniva Trade Dispute Update)


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will continue to closely monitor and report on these changing factors in future IRP and

competitive procurement filings.

In preparation for the HB 589 competitive procurement process, the Company continues to build its

relationships with suppliers, Engineering, Procurement, and Construction Contractors (EPCs), and

other entities to create greater efficiencies in the supply chain, reduce construction costs, reduce

operating and maintenance costs (O&M), and enhance system design. In anticipation of future solar

growth, DEC is positioning itself to properly integrate renewable resources to the grid regardless of

ownership.

In addition to ensuring DEC has operational control over future solar associated with HB 589, the

intermittency of solar output will require the Company to evaluate and invest in technologies to

provide solutions for voltage, volt-ampere reactive (VAR), and/or higher ancillary reserve

requirements.

HB 589 Customer Programs

In addition to the competitive procurement process, HB 589 offers direct renewable energy

procurement for major military installations, public universities, and other large customers, as well

as a community solar program. These programs will be a great complement to the existing customer

oriented strategies in DEC such as the Green Source Rider and SC DER Program.

The Green Source Rider allows DEC to procure renewable energy on behalf of the customer. The

customer pays for the REC during their project term and DEC may acquire the REC following the

contract term. Numerous customers have participated in this program, which stands at

approximately 99 MW-AC (nameplate capacity) and is expected to grow to just over 103 MW-AC

by 2017.

The renewable energy procurement carve out for large customers such as military installations and

universities may have similarities to the Green Source Rider program. The program allows for up to

600 MW of total capacity, with set asides for military installations (100 MW of the 600 MW) and

the UNC system (250 MW of the 600 MW). The 2017 IRP base case assumes all 600 MW of this

program materialize, with the DEC/DEP split expected to be roughly equal. If all 600 MW are not

utilized, the remainder will roll back to the competitive procurement, increasing its volume.


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The community solar portion of HB 589 calls for up to 20 MW of shared solar in DEC. This

program may have similarities to SC DER Programs community solar program. The 2017 IRP base

case assumes that all 20 MW of the program materialize.

HB 589 also calls for a rebate program for rooftop solar as well as a leasing program, and the

establishment of revised net metering rates. Given the uncertainty around the timing and structuring

of these programs, it is challenging to assess the impact HB 589 will have on rooftop solar adoption

in NC.

SC DER Program Solar

Steady progress continues to be made with the first two tiers of the SC DER Program summarized

below, unlocking the third tier:

Tier I: 40 MW of solar capacity from facilities each >1 MW and < 10 MW in size.

Tier II: 40 MW of behind-the-meter rooftop solar facilities for residential, commercial and

industrial customers, each 1 MW, 25% of which must be 20 kilowatts (kW). Since Tier

II is behind the meter, the expected solar generation is embedded in the load forecast as a

reduction to expected load.

Tier III: Investment by the utility in 40 MW of solar capacity from facilities each >1 MW

and


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and its customers to evaluate the costs and impacts of batteries deployed at a significant scale,

explore the nature of new offerings desired by customers, and fill knowledge gaps. Among the DEC

and DEP territories, as much as 75 MW of utility-owned and operated battery storage may be

dispersed in the 2019-2021 time period. Additionally, HB 589 calls for an energy storage study to

assess the economic potential for NC customers.

DEC considers wind a potential energy resource in the long term to support increased renewables

portfolio diversity and long-term general compliance need. Therefore, DEC issued a RFP on August

15, 2017 for delivered energy, capacity, and associated RECs from wind projects ranging in size

from 100 to 500 MW, and capable of delivering energy on or before December 31, 2022. To

represent the RFP, a placeholder of 200 MW was added to the 2017 IRP base case starting in 2023.

Summary of Expected Renewable Resource Capacity Additions

The 2017 IRP incorporates the base case renewable capacity forecast below. This case includes

renewable capacity required for compliance with SC DER Program, NC REPS, non-compliance

PURPA renewable purchases part of the Transition MW of HB 589, as well as Green Source

Rider, and the additional three components of HB 589 (competitive procurement, renewable energy

procurement for large customers, and community solar). The Company anticipates a diverse

portfolio including solar, biomass, hydro, wind, and other resources. Actual results could vary

substantially for the reasons discussed previously, as well as, other potential changes to legislative

requirements, tax policies, technology costs, and other market forces. The details of the forecasted

capacity additions, including both nameplate and contribution to winter and summer peaks are

summarized in Table 4-D below.

While solar does not normally reach its maximum output at the time of DECs expected peak load

in the summer, solars contribution to summer peak load is large enough (46% of nameplate solar

capacity) that it may push the time of summer peak from hour beginning 4:00 PM to 5:00 PM or

later if solar penetration levels continue to increase. However, solar is unlikely to have a similar

impact on the morning winter peak due to lower expected solar output in the morning hours (5% of

nameplate solar capacity). Contribution to peak assumptions will continue to be evaluated in 2018,

with specific attention given to different configurations of solar projects with fixed tilt or tracking

systems and different ILRs. Wind is assumed to contribute 13% of nameplate capacity to both the

winter and summer peaks.


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Table 4-D DEC Base Case Total Renewables

While high and low solar penetration scenarios were not evaluated compared to the base case for the

2017 IRP, volumes can certainly vary greatly, especially for solar resources. Solar installations may

fall short of the Base Case if the competitive procurement for universal solar facilities, renewable

energy procurement for large customers, and/or community solar programs of HB 589 dont

materialize to their limits for some of the reasons mentioned earlier. On the upside, there is also the

unknown of what occurs after HB 589 which is assumed to have no additional solar growth in the

Base Case. While new policy may stimulate additional growth, a high sensitivity could occur given

further improvements in the economics for solar through events such as high carbon dioxide

emission regulations or taxes, lower solar capital costs, economical solar plus storage, and/or

continuation of renewal subsidies, and/or stronger renewable energy mandates.

c) Nuclear Assumptions

In its last filed IRP on September 1, 2016, DEC indicated it continued to have a long-term need

for new nuclear generation. The Base Case scenario, which included a cost on carbon emissions,

assumed new nuclear resources to meet load and minimum planning reserve margin with Lee

Nuclear additions in 2026 and 2028 (2,234 MW).

On December 19, 2016, the Company received the Combined Construction and Operating

License (COL) for the Lee Nuclear Project from the U.S. Nuclear Regulatory Commission. On

August 25, 2017, DEC filed a request to cancel the Lee Nuclear Project as that project was

originally envisioned and included in prior IRPs. On August 25th, DEC filed notice of its request

Solar

Biomass/

Hydro Wind Total Solar

Biomass/

Hydro Wind Total Solar

Biomass/

Hydro Wind Total

2018 889 121 0 1010 409 121 0 530 2017/2018 34 121 0 155

2019 1214 116 0 1330 558 116 0 674 2018/2019 44 116 0 160

2020 1333 115 0 1448 613 115 0 728 2019/2020 61 115 0 176

2021 1711 115 0 1826 787 115 0 902 2020/2021 67 115 0 182

2022 2088 96 0 2184 960 96 0 1056 2021/2022 86 96 0 182

2023 2482 90 200 2572 1142 90 26 1232 2022/2023 104 90 26 194

2024 2890 88 200 2978 1329 88 26 1417 2023/2024 124 88 26 212

2025 2963 86 200 3049 1363 86 26 1449 2024/2025 144 86 26 230

2026 2949 77 200 3026 1356 77 26 1433 2025/2026 148 77 26 225

2027 2934 74 200 3008 1350 74 26 1424 2026/2027 147 74 26 221

2028 2919 76 200 2995 1343 76 26 1419 2027/2028 147 76 26 223

2029 2905 76 200 2981 1336 76 26 1412 2028/2029 146 76 26 222

2030 2890 73 200 2963 1329 73 26 1402 2029/2030 145 73 26 218

2031 2890 66 200 2956 1329 66 26 1395 2030/2031 145 66 26 211

2032 2890 60 200 2950 1329 60 26 1389 2031/2032 145 60 26 205

* Solar includes 0.5% per year degradation

DEC Base Renewables - Compliance + Non-Compliance

MW Nameplate MW Contribution to Summer Peak MW Contribution to Winter Peak


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with the Public Service Commission of South Carolina in Docket 2011-20-E. Also, that request is

now pending before the NCUC in Docket Nos. E-7, Sub 819 and E-7 Sub 1146. DECs decision

to cancel the project resulted from events that have occurred subsequent to receipt of the Lee

Nuclear COL. These events include the AP-1000 technology owner, designer and engineer,

Westinghouse, and its parent company, Toshiba Corporation, indicating that they intend to exit

the nuclear construction business in the U.S., including the Lee Project; the subsequent

bankruptcy of Westinghouse, and the substantial cost increases and schedule delays associated

with the Vogtle and V.C. Summer new nuclear construction projects; the latter of which SCE&G

and project joint owner, Santee Cooper, recently canceled.

In addition to these developments, revised projections indicate that new nuclear baseload

capacity is needed only under a carbon-constrained scenario with the assumption of no existing

nuclear re-licensing. Even in that scenario, the added capacity would not be needed until much

later in the 15-year planning horizon (2031, 2033) than projected in the 2016 IRP.

The Company views all of its existing nuclear fleet as excellent candidates for license

extensions, however to date, no existing nuclear plant operating licenses have been extended

from 60 years to 80 years in the United States. As such, there is uncertainty regarding license

extension, and any costs associated with continuing to operate for an additional 20 years. Given

the uncertainty of license extension, the IRP Base Case does not assume license extension at this

time, but rather considers relicensing as a sensitivity to the Base Case. The Company is

evaluating the feasibility of relicensing its existing nuclear resources. A discussion of the

Companys activities is included below.

Subsequent License Renewal (SLR) for Nuclear Power Plants

License Renewal is governed by Title 10 of the Code of Federal Regulations (10 CFR) Part 54,

Requirements for Renewal of Operating Licenses for Nuclear Power Plants. Additionally, the

NRC has issued regulatory guidance documents, specifically the Generic Aging Lessons Learned

(GALL) Report (NUREG-1801) and U.S. Nuclear Regulatory Commission Regulation-1800

(NUREG-1800), Standard Review Plan for Review of License Renewal Applications for Nuclear

Power Plants (SRP-LR) as a basis for determining the adequacy of Aging Management

Programs (AMPs). Currently the Nuclear Regulatory Commission (NRC) has approved

applications to extend licenses to 60 years for 87 nuclear units with applications for 5 nuclear

units currently under review.

On August 29, 2014 the Nuclear Regulatory Commission issued a Staff Requirements

Memorandum to provide the NRC staff with direction on SLR, i.e., extending nuclear power

plant licenses to 80 years. Consistent with that direction, the NRC drafted guidance documents


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specifically applicable to SLR applications. In December 2015, NUREG-2191 (Generic Aging

Lessons Learned for Subsequent License Renewal (GALL-SLR) Report) and NUREG-2192

(Standard Review Plan for the Review of Subsequent License Renewal (SRP-SLR) Applications

for Nuclear Power Plants) were issued for public comment. Following an extensive comment

process involving Duke Energy, the nuclear industry, and other stakeholders, the NRC published

the final NUREGs in the Federal Register on July 14, 2017, thereby establishing formal

regulatory guidance for SLR.

Dominion Energy announced on November 6, 2015 that it would pursue SLR for its Surry plant

as a Lead Plant and submitted a letter of intent to the NRC. Exelon Corporation made a similar

announcement for its Peach Bottom plant on June 7, 2016. Currently, Exelon is planning to

submit the Peach Bottom SLR Application in mid-2018 while Dominion is targeting early- 2019

for Surry. On May 17, 2017 a third utility notified the NRC of its intent to submit an SLR

application by the end of 2017. The letter providing the notification was submitted requesting

withholding information from public disclosure and as a result the name of the utility and

licensee(s) is not publicly available.

Duke Energy is considering Oconee Nuclear Station (ONS) for submission of its first SLR

application to extend the licenses to 80 years. The remaining nuclear sites will follow where the

cost/benefit proves acceptable.

An Advance Funding was approved on May 12, 2016 for the development portion of the ONS

SLR project. These funds are being used to further develop and refine the Project Plan including

scope, schedule, cost, risk, and other project elements. At this time, a final decision to extend the

ONS or any other Duke Energy nuclear power plants' operating licenses to 80 years has not been

made.

d) Combined Heat and Power

Combined Heat and Power systems, also known as cogeneration, generate electricity and useful

thermal energy in a single, integrated system. CHP is not a new technology, but an approach to

applying existing technologies. Heat that is normally wasted in conventional power generation is

recovered as useful energy, which avoids the losses that would otherwise be incurred from separate

generation of heat and power. CHP incorporating a gas-fired combustion turbine (CT) and heat

recovery steam generator (HRSG) is more efficient than the conventional method of producing

power and usable heat separately with a CT/generator and a stand-alone steam boiler.


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Duke Energy is exploring and working with potential customers with good base thermal loads on a

regulated Combined Heat and Power offer. The CHP asset is included as part of Duke Energys

IRP as a placeholder for future projects as described below. The steam sales are credited back to the

revenue requirement of the projects to reduce the total cost of this resource. Along with the

potential to be a cost-competitive generation resource, CHP can result in carbon dioxide (CO2)

emission reductions, and is a potential economic development opportunity for the state.

DEC has signed agreements and obtained regulatory approval for a 15 MW CHP at Clemson

University, which is expected to be in service by 2020. Filing for a Certificate of Public

Convenience and Necessity (CPCN) for a 21 MW CHP at Duke University has been delayed

pending the resolution of issues raised by the University. Discussions with other potential steam

hosts are currently underway.

Projections for CHP have been included in the following quantities in this IRP:

2020: 43 MW (winter) / 40 MW (summer)

2022: 43 MW (winter) / 40 MW (summer)

As CHP development continues, future IRPs will incorporate additional CHP as appropriate.

Additional technologies evaluated as part of this IRP are discussed in Chapter 7.

e) Resource Adequacy

Background

Resource adequacy refers to the ability of the electric system to supply the aggregate electrical

demand and energy requirements of the end-use customers at all times, taking into account

scheduled and reasonably expected unscheduled outages of system elements. Utilities require a

margin of reserve generating capacity in order to provide reliable service. Periodic scheduled

outages are required to perform maintenance, inspect generating plant equipment, and to refuel

nuclear plants. Unanticipated mechanical failures may occur at any given time, and may require

shutdown of equipment to repair failed components. Adequate reserve capacity must be available

to accommodate these unplanned outages and to compensate for higher than projected peak demand

due to forecast uncertainty and weather extremes. The Company utilizes a reserve margin target in

its IRP process to ensure resource adequacy. Reserve margin is defined as total resources minus

peak demand, divided by peak demand. The reserve margin target is established based on

probabilistic assessments as described below.


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2016 Resource Adequacy Study

The Company retained Astrap Consulting in 2016 to conduct an updated resource adequacy study.

The updated study was warranted due to two primary factors.3 First, the extreme weather

experienced in the service territory in recent winter periods was so impactful to the system that

additional review with the inclusion of recent years weather history was warranted. Second, the

system has added, and projects to add, a large amount of solar resources that provide meaningful

capacity benefits in the summer but very little capacity benefits in the winter. Solar resources

contribute approximately 45% (DEC 46%, DEP 44%) of nameplate capacity at the time of the

expected summer peak demand which typically occurs during afternoon hours. However, solar

resources only contribute about 5% of nameplate capacity at the time of expected winter peak

demand which typically occurs during early morning hours. As discussed in the Renewables

section of this document, there is a potential to add significantly to the solar resources already

incorporated on the system.

Methodology

The 2016 resource adequacy study incorporated the uncertainty of weather, economic load growth,

unit availability, and the availability of transmission and generation capacity for emergency

assistance. Astrap analyzed the optimal planning reserve margin based on providing an acceptable

level of physical reliability and minimizing economic costs to customers. The most common

physical reliability metric used in the industry is to target a system reserve margin that satisfies the

one day in 10 years Loss of Load Expectation (LOLE) standard. This standard is interpreted as one

firm load shed event every 10 years due to a shortage of generating capacity. From an economic

perspective, as planning reserve margin increases, the total cost of reserves increases while the costs

related to reliability events decline. Similarly, as planning reserve margin decreases, the cost of

reserves decreases while the costs related to reliability events increase, including the costs to

customers for loss of power. Thus, there is an economic optimum point where the cost of additional

reserves plus the cost of reliability events to customers is minimized.

Winter Capacity Planning

3 Astrap Consulting is an energy consulting firm with expertise in resource adequacy and integrated resource

planning.


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In the past, loss of load risk was typically concentrated during the summer months and a summer

reserve margin target provided adequate reserves in the summer and winter. However, the

incorporation of recent winter load data and the significant amount of solar penetration in the

updated study, shows that the majority of loss of load risk is now heavily concentrated during the

winter period. Since solar capacity contribution to peak is much greater in the summer compared to

the winter, maintaining a summer reserve margin target would result in declining winter reserve

margins over time due to the impact on summer versus winter reserves as solar capacity increases.

Thus, use of a summer reserve margin target will no longer ensure that adequate reserve levels are

maintained in the winter, and winter load and resources now drive the timing need for new capacity

additions. As a result, a winter planning reserve margin target is now needed to ensure that adequate

resources are available throughout the year to meet customer demand.

It is noted that the primary driver for the shift to winter capacity planning is the high penetration of

solar resources and the associated impact on summer versus winter reserves. Winter load volatility

impacts LOLE and puts upward pressure on the reserve margin target; however, winter load

volatility or the seasonality of summer versus winter peaks is not the driver for the shift to winter

capacity planning.

Results

Based on results of the 2016 resource adequacy assessment, the Company has adopted a 17%

minimum winter reserve margin target for scheduling new resource additions. The Company will

continue to monitor its generation portfolio and other planning assumptions that can impact resource

adequacy and initiate new studies as appropriate.

Adequacy of Projected Reserves DECs resource plan reflects winter reserve margins ranging from approximately 17% to 22%.

Reserves projected in DECs IRP meet the minimum planning reserve margin target and thus

satisfy the one day in 10 years LOLE criterion. Projected reserve margins often exceed the

minimum 17% winter target by 3% or more in years immediately following new resource

additions. For example, reserves exceed the 17% minimum target by 3% or more during

2017/2018 through 2019/2020 as a result of the addition of the Lee combined cycle unit in the Fall

of 2017 combined with a reduction in the wholesale load forecast beginning 2019. Reserves also

exceed the minimum 17% target by 3% or more as a result of resource additions in 2024/2025,

2028/2029 and 2031/2032.


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The IRP provides general guidance in the type and timing of resource additions. As previously

noted, projected reserve margins will often be somewhat higher than the minimum target in years

immediately following new generation additions since capacity is generally added in large blocks to

take advantage of economies of scale. Large resource additions are deemed economic only if

they have a lower Present Value Revenue Requirement (PVRR) over the life of the asset as

compared to smaller resources that better fit the short-term reserve margin need. Reserves

projected in the Companys IRP are appropriate for providing an economic and reliable power

supply.

f) Fuel Costs

Similar to the 2015 IRP and the 2016 Biennial IRP Report, the first 10 years of natural gas prices

are based on market data and the remaining years are based off of fundamental pricing.

Specifically, DEC and DEP are using market based prices for the first 10 years of the planning

period (2018 2027). Following the 10 years of market prices, the Companies transition to

fundamental pricing over a 5 year period with 100% fundamental pricing in 2033 and beyond.

Market prices represent liquid, tradable gas prices offered at the present time, also called future or

forward prices. These prices represent an actual contractually agreed upon price that willing buyers

and sellers agree to transact upon at a specified future date. As such, assuming market liquidity,

they represent the markets view of prices for a given point in the future. Fundamental prices

developed through external econometric modeling, on the other hand, represent a projection of fuel

prices into the future taking into account changing supply and demand assumptions in the context of

the changing dynamics of the external marketplace. The natural gas market is a liquid market with

multiple buyers and sellers of natural gas that are willing to transact at longer transaction terms.

To provide price discovery and demonstrate continued market liquidity, the Company has

purchased a fixed price natural gas forward swap for 2,500 million British Thermal Units per day

(MMBtu/day) extending nearly ten years forward. It is worth noting that this purchase shows a

continued decline in natural gas prices. The 10-year average price for the most recent purchase,

executed on August 17, 2017, was lower than a similar purchase made in April of 2017 and lower

than the prices used in the development of the 2016 IRP.

As in the 2016 Biennial IRP Report, coal prices continue to be based on 5 years of market data in

the 2017 IRP. Following the 5 years of market prices, the Companies transition to fundamental

pricing over a 5-year period with 100% fundamental pricing in 2028.


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g) Carbon Assumptions

On August 3, 2015, the EPA finalized a rule establishing CO2 new source performance standards

for pulverized coal (PC) and natural gas combined cycle (NGCC or CC) electric generating units

(EGUs) that initiate construction after January 8, 2014. The EPA finalized emission standards of

1,400 lb CO2 per gross megawatt-hour (MWh) of electricity generation for PC units and 1,000 lb

CO2 per gross MWh for NGCC units. The standard for PC units can only be achieved with carbon

capture and sequestration technology. Numerous parties filed petitions with the U.S. Court of

Appeals for the District of Columbia (D.C. Circuit) challenging the EPAs final emission standard

for new PC units. Briefing in the case is complete, but oral argument is not currently scheduled. On

April 28, 2017, the D.C. Circuit ordered that the litigation be suspended while it considers a motion

from EPA to hold the case in abeyance. The court has not ruled on EPAs motion.

In response to a March 28, 2017 Executive Order, the EPA has undertaken a review of the rule to

determine whether it should be suspended, revised, or rescinded. The rule remains in effect pending

the outcome of litigation and EPAs review of the rule. The EPA has not announced a schedule for

completing its review.

On August 3, 2015, the EPA finalized the Clean Power Plan, a rule to limit CO2 emissions from

existing fossil fuel-fired EGUs (existing EGUs are units that commenced construction prior to

January 8, 2014). The CPP required states to develop and submit to EPA for approval

implementation plans designed to achieve the required CO2 emission limitations. The CPP required

states to submit initial plans by September 6, 2016, and final plans by September 6, 2018. The CPP

established two rate-based compliance pathways and two mass-based compliance pathways for

states to choose from when developing their state implementation plans. The CPP required

emission limitations to take effect beginning in 2022 and get gradually more stringent through 2030.

Numerous legal challenges to the CPP were filed with the D.C. Circuit. On February 9, 2016 the

Supreme Court issued a stay in the case, halting implementation of the CPP through any final

decision in the case by the Supreme Court. This means the CPP has no legal effect, and EPA

cannot enforce any of the deadlines or rule requirements while the stay is in place.

Briefing of the case before the D.C. Circuit was completed in April, 2016. Oral argument before the

full D.C. Circuit occurred on September 27, 2016. The D.C. Circuit has not issued a decision in the

case. On April 28, 2017, the D.C. Circuit ordered that the litigation be suspended while it considers

a motion from EPA to hold the case in abeyance. The court has not ruled on EPAs motion.


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In response to the March 28, 2017 Executive Order, EPA initiated a review of the CPP to determine

whether it should be suspended, revised, or rescinded. On June 8, 2017, the EPA sent a proposed

rule to the Office of Management and Budget to repeal the CPP. Once interagency review is

complete, EPA will issue the proposal for public comment. EPA has yet to announce what it will

do regarding the possible replacement of the CPP with another rule. There is no schedule for EPA to

issue the proposal or to determine what it will do regarding replacement of the CPP.

In light of the uncertainty of future carbon legislation, the Base Case assumes a carbon cost

beginning in 2026.

h) Transmission Planned or Under Construction

This section lists the planned transmission line additions and discusses the adequacy of DECs

transmission system. Table 5-E lists the line projects that are planned to meet reliability needs.

Table 4-E: DEC Transmission Line Additions

Location Capacity Voltage

Year From To MVA KV Comments

2020 Lincoln CTs Longview Tie N/A 230

Install new

230/100 kV tie

station in

existing double

circuit line near

Maiden, NC

There are presently no new lines, 161 kV and above, under construction in DECs service area.

DEC Transmission System Adequacy

Duke Energy Carolinas monitors the adequacy and reliability of its transmission system and

interconnections through internal analysis and participation in regional reliability groups. Internal

transmission planning looks 10 years ahead at available generating resources and projected load to

identify transmission system upgrade and expansion requirements. Corrective actions are planned

and implemented in advance to ensure continued cost-effective and high-quality service. The DEC

transmission model is incorporated into models used by regional reliability groups in developing

plans to maintain interconnected transmission system reliability. DEC works with DEP, North


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Carolina Electric Membership Corporation (NCEMC) and ElectriCities to develop an annual NC

Transmission Planning Collaborative (NCTPC) plan for the DEC and DEP systems in both South

and North Carolina. In addition, transmission planning is coordinated with neighboring systems

including SCE&G and Santee Cooper under a number of mechanisms including legacy interchange

agreements between SCE&G, Santee Cooper, DEP, and DEC.

The Company monitors transmission system reliability by evaluating changes in load, generating

capacity, transactions and topography. A detailed annual screening ensures compliance with DECs

Transmission Planning Guidelines for voltage and thermal loading. The annual screening uses

methods that comply with SERC Reliability Council (SERC) policy and North American Electric

Reliability Corporation (NERC) Reliability Standards and the screening results identify the need for

future transmission system expansion and upgrades.

Transmission planning and requests for transmission service and generator interconnection are

interrelated to the resource planning process. DEC currently evaluates all transmission reservation

requests for impact on transfer capability, as well as compliance with the Companys Transmission

Planning Guidelines and the Federal Energy Regulatory Commission (FERC) Open Access

Transmission Tariff (OATT). The Company performs studies to ensure transfer capability is

acceptable to meet reliability needs and customers expected use of the transmission system.

Generator interconnection requests are studied in accordance with the Large and Small Generator

Interconnection Procedures in the OATT.

SERC audits DEC every three years for compliance with NERC Reliability Standards. Specifically,

the audit requires DEC to demonstrate that its transmission planning practices meet NERC

standards and to provide data supporting the Companys annual compliance filing certifications.

SERC conducted a NERC Reliability Standards compliance audit of DEC in December 2016. The

scope of this audit included standards impacting the Transmission Planning area. DEC received

No Findings from the audit team in the Transmission Planning area.

DEC participates in a number of regional reliability groups to coordinate analysis of regional, sub-

regional and inter-balancing authority area transfer capability and interconnection reliability. The

reliability groups purpose is to:

Assess the interconnected systems capability to handle large firm and non-firm

transactions for purposes of economic access to resources and system reliability;


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Ensure that planned future transmission system improvements do not adversely

affect neighboring systems; and

Ensure interconnected system compliance with NERC Reliability Standards.

Regional reliability groups evaluate transfer capability and compliance with NERC Reliability

Standards for the upcoming peak season and five- and ten-year periods. The groups also perform

computer simulation tests for high transfer levels to verify satisfactory transfer capability.

Application of the practices and procedures described above have ensured DECs transmission

system is expected to continue to provide reliable service to its native load and firm transmission

customers.


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5. LOAD FORECAST:

Methodology

The Duke Energy Carolinas Spring 2017 Forecast provides projections of the energy and peak

demand needs for its service area. The forecast covers the time period of 2018 2032 and

represents the needs of the following customer classes:

Residential

Commercial

Industrial

Other Retail

Wholesale

Energy projections are developed with econometric models using key economic factors such as

income, electricity prices, and industrial production indices, along with weather and appliance

efficiency trends. Population projections are used in the Residential customer model.

The economic projections used in the Spring 2017 Forecast are obtained from Moodys Analytics, a

nationally recognized economic forecasting firm, and include economic forecasts for the Carolinas.

The Retail forecast consists of the three major classes: Residential, Commercial, and Industrial.

The Residential class sales forecast is comprised of two projections. The first is the number of

residential customers, which is driven by population. The second is energy usage per customer,

which is driven by variables such as weather, regional economic and demographic trends, electric

prices, and efficiency trends.

The usage per customer forecast was derived using a Statistical Adjusted End-Use Model (SAE).

This is a regression based framework that uses projected appliance saturation and efficiency trends

developed by ITRON using Energy Information Agency (EIA) data. It incorporates naturally

occurring efficiency trends and government mandates more explicitly than other models. The

outlook for usage per customer is slightly negative through much of the forecast horizon, so most of

the growth in sales is related to customer (population) increases. The projected growth rate of the

Residential class after considering all impacts (i.e., customer growth, energy efficiency, behind-the-

meter solar, etc.) is 0.9% for the period 2018-2032.


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The Commercial forecast also uses a SAE model in an effort to reflect naturally occurring as well as

government mandated efficiency changes. The three largest sectors in the Commercial class are

Offices, Education and Retail. The projected growth rate of commercial in the Spring 2017 Forecast

after considering all impacts, is 0.2% for the period 2018 to 2032.

The Industrial class is forecasted using a standard econometric model, with drivers such as

industrial production and the price of electricity. Overall, Industrial sales are expected to grow 0.5%

over the forecast horizon, after all impacts.

System peak demands were projected using the SAE approach in the Spring 2017 Forecast. The

peak forecast was developed using a monthly SAE model, similar to the sales SAE models, which

includes monthly appliance saturations and efficiencies, interacted with weather and the fraction of

each appliance type that is in use at the time of the monthly peak. Over the forecast period, the

summer peak demand is expected to grow 0.4% (after all impacts), while the winter peak demand is

growing 0.9% (after all impacts).

Weather impacts are incorporated into the models by using Heating Degree Days with a base

temperature of 59 and Cooling Degree Days with a base temperature of 65. The forecast of degree

days is based on a 30-year average, which is updated every year.

Forecast Enhancements

In 2013, The Company began using the statistically adjusted end use models (SAE) provided by

ITRON to forecast sales and peaks. The end use models provide a better platform to recognize

trends in equipment /appliance saturation and changes to efficiencies, and how those trends interact

with heating, cooling, and other or non-weather related sales. The appliance saturation and

efficiency trends are developed by ITRON using data from the EIA. ITRON is a recognized firm

providing forecasting services to the electric utility industry. These appliance trends are used in the

residential and commercial sales models. In conjunction with peer utilities and ITRON, the

company continually looks for refinements to its modeling procedures to make better use of the

forecasting tools, and develop more reliable forecasts.

Each time the forecast is updated, the most currently available historical and projected data is used.

The Spring 2017 forecast utilizes:

Moodys Analytics January 2017 base economic projections.


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End use equipment and appliance indexes reflect the 2016 update of ITRONs end-use data,

which is consistent with the Energy Information Administrations 2016 Annual Energy

Outlook.

A calculation of normal weather using the period 1987-2016.

Additional focus is being placed on the hourly shaping of sales, which plays a critical role in

forecasting summer and winter peaks. While much of this work is ongoing and will be incorporated

in the 2018 IRPs we continue to review the weather sensitivity of winter and summer peaks, as

well as the hourly shaping of behind-the-meter solar, UEE, electric vehicles, and other variables.

Additional focus is also being placed on Duke's load research sample data, to gain a better

understanding of historical hourly demand trends, winter and summer peaking characteristics by

customer class, and minimums by customer class, in our continuous effort to improve forecast

accuracy.

Assumptions

Below are the projected average annual growth rates of several key drivers from DECs Spring

2017 Forecast.

2018-2032

Real Income 2.7%

Manufacturing Industrial Production Index (IPI) 1.3%

Population 1.6%

In addition to economic, demographic, and efficiency trends, the forecast also incorporates the

expected impacts of utility sponsored energy efficiency programs, as well as projected effects of

electric vehicles and behind-the-meter solar technology.

Wholesale

The wholesale contracts are included in the forecasted sales and peaks in the following tables.

Please note that Duke is expected to lose a portion of wholesale load in support of NTE Energy

(Kings Mountain combined cycle ) resource. For a complete description of the Wholesale forecast,

please see Chapter 11.


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Historical Values

It should be noted that long-term decline of the Textile industry and the recession of 2008-2009

have had an adverse impact on DEC sales. The worst of the Textile decline appears to be over, and

Moodys Analytics expects the Carolinas economy to show solid growth going forward.

In tables 5-A & 5-B below the history of DEC customers and actual sales are given.

Table 5-A Retail Customers (Thousands, Annual Average)

Table 5-B Electricity Sales (GWh Sold - Years Ended December 31)

Note the values in Table 5-B are not weather adjusted.

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Avg Annual

Growth Rate

Residential

1,916 2,012 2,024 2,034 2,041 2,053 2,068 2,089 2,117 2,148 1.3%

Commercial

322 334 331 333 335 337 339 342 345 349 0.9%

Industrial

7 7 7 7 7 7 7 7 6 6 -1.0%

Other

13 14 14 14 14 14 14 15 15 15 1.8%

Total

2,258 2,367 2,376 2,388 2,397 2,411 2,428 2,453 2,483 2,519 1.2%

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Avg Annual

Growth Rate

Residential 27,459 27,335 27,273 30,049 28,323 26,279 26,895 27,976 27,916 27,939 0.3%

Commercial 27,433 27,288 26,977 27,968 27,593 27,476 27,765 28,421 28,700 28,906 0.6%

Industrial 23,948 22,634 19,204 20,618 20,783 20,978 21,070 21,577 22,136 21,942 -0.8%

Other 278 284 287 287 287 290 293 303 305 304 1.0%

Total Retail 79,118 77,541 73,741 78,922 76,986 75,023 76,023 78,277 79,057 79,091 0.1%

Wholesale 2,454 3,525 3,788 5,166 4,866 5,176 5,824 6,559 6,916 7,614 14.3%

Total System 81,572 81,066 77,529 84,088 81,852 80,199 81,847 84,836 85,973 86,705 0.7%


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Utility Energy Efficiency

UEE continues to have a large impact in the acceleration of the adoption of energy efficiency. When

including the energy and peak impacts of UEE, careful attention must be paid to avoid the double

counting of UEE efficiencies with the naturally occurring efficiencies included in the SAE

modeling approach. To ensure there is not a double counting of these efficiencies, the forecast rolls

off the UEE savings at the conclusion of its measure life. For example, if the accelerated benefit

of a residential UEE program is expected to have occurred 7 years before the energy reduction

program would have been otherwise adopted, then the UEE effects after year 7 are subtracted

(rolled off) from the total cumulative UEE. With the SAE models framework, the naturally

occurring appliance efficiency trends replace the rolled off UEE benefits serving to continue to

reduce the forecasted load resulting from energy efficiency adoption.

Table 5-C below illustrates this process:

Column A: Total energy before reduction of future UEE

Column B: Historical UEE Roll-Off

Column C: Forecasted UEE Incremental Roll-On

Column D: Forecasted UEE Incremental Roll-Off

Column E: UEE amount to subtract from Column A

Column F: Total energy after incorporating UEE (column A less column E)


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Table 5-C UEE Program Life Process (GWh)

Results

A tabulation of the utilitys forecasts for 2018-2032, including peak loads for summer and winter

seasons of each year and annual energy forecasts, both with and without the impact of UEE

programs, are shown below in Tables 5-F and 5-G.

Load duration curves, with and without UEE programs, follow Tables 5-F and 5-G, and are shown

as Charts 5-A and 5-B.

The tables below show the results of the forecast:

Table 5-D: Total retail customers by class

Table 5-E: Retail sales (at the meter) after the impacts of energy efficiency

Table 5-F: Forecasted system summer peak, winter peak, and sales before including the

impact of utility sponsored energy efficiency programs (at generation)

Chart 5-A: Load duration curve before including the impact of utility sponsored energy

efficiency programs

Forecast Historical UEE Forecasted UEE Forecasted UEE UEE to Subtract Forecast

Before UEE Roll Off Incremental Roll on Incremental Roll Off From Forecast After UEE

2017 95,326 0 422 0 422 94,903

2018 96,506 9 777 0 786 95,739

2019 96,269 37 1,134 0 1,172 95,172

2020 97,251 95 1,482 0 1,576 95,864

2021 98,121 193 1,820 0 2,013 96,495

2022 98,589 328 2,157 0 2,484 96,761

2023 99,470 484 2,496 4 2,984 97,461

2024 100,395 646 2,815 9 3,469 98,234

2025 101,169 790 3,127 24 3,941 98,856

2026 102,005 901 3,460 66 4,428 99,513

2027 102,814 981 3,898 105 4,984 100,001

2028 103,613 1,029 4,764 527 6,321 100,405

2029 104,214 1,054 6,696 2,144 9,895 100,716

2030 104,733 1,066 7,018 2,250 10,335 101,032

2031 105,287 1,070 7,288 2,338 10,697 101,407

2032 105,871 1,070 7,511 2,410 10,991 101,840


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Table 5-G: Forecasted system summer peak, winter peak, and sales after including the

impact of utility sponsored energy efficiency programs (at generation)

Chart 5-B: Load duration curve after including the impact of utility sponsored energy

efficiency programs

Table 5-D Retail Customers (Thousands, Annual Average)

Residential Commercial Industrial Other Retail

Customers Customers Customers Customers Customers

2018 2,198 356 6 15 2,576

2019 2,220 359 6 16 2,601

2020 2,243 362 6 16 2,627

2021 2,266 365 6 16 2,652

2022 2,289 367 6 16 2,678

2023 2,312 370 6 16 2,704

2024 2,335 374 6 16 2,731

2025 2,359 376 6 17 2,758

2026 2,383 379 6 17 2,785

2027 2,407 382 6 17 2,812

2028 2,432 385 6 17 2,839

2029 2,457 388 6 17 2,867

2030 2,481 391 5 17 2,895

2031 2,507 394 5 18 2,924

2032 2,532 397 5 18 2,953

Avg. Annual

Growth Rate 1.0% 0.8% -0.8% 1.0% 1.0%


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Table 5-E Retail Sales (GWh Sold - Years Ended December 31)

Residential Commercial Industrial Other Retail

Gwh Gwh Gwh Gwh Gwh

2018 27,702 28,564 22,368 299 78,933

2019 27,773 28,631 22,608 297 79,310

2020 27,945 28,717 22,927 294 79,884

2021 28,138 28,747 23,253 291 80,429

2022 28,372 28,805 23,425 288 80,891

2023 28,650 28,904 23,646 286 81,486

2024 28,950 29,053 23,847 285 82,135

2025 29,240 29,139 24,009 283 82,671

2026 29,540 29,267 24,135 280 83,222

2027 29,823 29,347 24,157 278 83,605

2028 30,103 29,422 24,092 277 83,895

2029 30,367 29,435 24,035 276 84,113

2030 30,649 29,403 24,004 274 84,331

2031 30,946 29,390 23,993 273 84,602

2032 31,255 29,421 23,964 272 84,912

Avg. Annual

Growth Rate 0.9% 0.2% 0.5% -0.7% 0.5%


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Table 5-F Load Forecast without Energy Efficiency Programs (at Generation)

Note: Table 7-A differs from these values due to a 47 MW PMPA backstand contract through 2020.

SUMMER WINTER ENERGY

(MW) (MW) (GWH)

2018 18,953 18,770 96,515

2019 18,908 18,818 96,306

2020 19,109 19,033 97,346

2021 19,267 19,230 98,314

2022 19,368 19,409 98,917

2023 19,531 19,639 99,954

2024 19,690 19,908 101,041

2025 19,860 20,088 101,959

2026 20,060 20,324 102,907

2027 20,250 20,548 103,795

2028 20,416 20,800 104,643

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